Gasification of coal, residue oil, and other refinery waste is frequently integrated with combined-cycle power plants (IGCC) to produce additional electricity. The syngas from the gasification predominantly comprises H2, CO2, CO, H2S and COS is therefore often treated to remove sulfur where the syngas is used as fuel gas to the power plant. While such IGCC plants are reasonably efficient in upgrading low-grade carbonaceous products to generate electricity, significant carbon and sulfur emissions are often generated, particularly from the exhaust of the combustion gas turbines (e.g., sulfurous oxides, CO2, etc.).
Numerous approaches have been undertaken to reduce CO2 emissions, and an exemplary typical method is described in U.S. Pat. No. 5,832,712 to Ronning et al, where gas turbine exhaust is treated for CO2 removal using a solvent. However, all or almost all of these processes tend to be cost prohibitive and energy inefficient due to the operation at atmospheric pressure and the relatively low CO2 partial pressure in the gas turbine exhaust. Alternatively, one or more membranes can be used to physically separate H2 and CO2 from the syngas upstream of a gas turbine. Membrane systems are often highly adaptable with respect to gas volumes and product-gas specifications. However, where stringent CO2 dioxide removal is required, membrane systems typically require multiple stages and recompression between the stages, which is often cost prohibitive.
In other approach, a chemical solvent is used that reacts with the acid gas to form a (typically non-covalent) complex with the acid gas. In processes involving a chemical reaction between the acid gas and the solvent, syngas is typically scrubbed with an alkaline salt solution of a weak inorganic acid as, for example, described in U.S. Pat. No. 3,563,695, or with alkaline solutions of organic acids or bases as, for example, described in U.S. Pat. No. 2,177,068. However, chemical solvents generally require extensive heating and lean solvent cooling and often further require high solvent recirculation, which increases proportionally with the acid gas concentration in the syngas. Therefore, such processes are suitable for treating unshifted syngas with low acid gas content but are problematic in treating shifted syngas that contains large amount of CO2 (e.g., greater than 30 vol %).
In a still further approach, physical solvents are used for acid gas removal. Physical solvents are particularly advantageous where the syngas has relatively high CO2 partial pressure (e.g., shifted syngas) as acid gas absorption increases proportionally with the CO2 partial pressure. The physical absorption of the acid gases is further dependent upon the selective solvent physical properties, the feed gas composition, pressure, and temperature. For example, methanol may be used as a low-boiling organic physical solvent, as exemplified in U.S. Pat. No. 2,863,527. However, such solvent requires low temperature refrigeration for solvent cooling, which is energy intensive.
Alternatively, physical solvents may be operated at ambient or slightly below ambient temperatures, including propylene carbonates as described in U.S. Pat. No. 2,926,751 and those using N-methylpyrrolidone or glycol ethers as described in U.S. Pat. No. 3,505,784. While such solvents may advantageously reduce cooling requirements, most propylene carbonate-based absorption processes are very efficient especially in CO2 removal from high pressure feed gas. In further known methods, physical solvents may also include ethers of polyglycols, and specifically dimethoxytetraethylene glycol as shown in U.S. Pat. No. 2,649,166, or N-substituted morpholine as described in U.S. Pat. No. 3,773,896. While use of physical solvents can significantly reduce the energy requirement, various difficulties still exist. Among other things, CO2 and H2S removal are often inefficient and incomplete, failing to meet today's stringent emission requirements. Moreover, where the acid gas is H2S, co-absorption of CO2 is very high, which is problematic for downstream sulfur plants.
An exemplary known gas treatment configuration that employs a physical solvent for H2S removal is depicted in Prior Art FIG. 1, in which unshifted synthesis gas 1 is treated using a H2S selective solvent stream 9 in absorber 50. The rich solvent from absorber, stream 4, is reduced in pressure via valve 54, forming stream 10 that is then flashed to separator 55. Almost all of the H2 and at least a portion of the CO2 in the rich solvent are recovered by recycling the flashed gas to the absorber, using compressor 56 via streams 22 and 2. The flashed liquid stream 12 is further letdown in pressure via valve 57 to form stream 13, which is heated by heat exchanger 58 to form stream 14. The rich solvent is regenerated in regenerator 59 producing an acid gas stream 15 and a lean solvent 16. Reboiler 61 and cooler 60 are used to supply the heating and cooling requirements of regeneration. The lean solvent is further pumped by pump 62, cooled in exchanger 58 and 66 via streams 17 and 18, respectively, providing a cooled lean solvent stream 9 to the absorber. The treated syngas stream 6 is then used as fuel gas to an IGCC power plant 53 via stream 5, and optionally as feed gas 7 to a hydrogen purification unit 52 that may further include membrane separators and pressure swing absorption beds.
It should be recognized that in such configurations physical solvent treating is limited by physical equilibrium of the acid gases in the solvent. While physical solvent can be advantageously regenerated by reduction in pressure to some extent without the use of heat, physical solvents require costly low temperature refrigeration (e.g., −40° F. and lower) for removal of H2S and COS to low levels (e.g., below 4 ppmv). Almost all solvent processes co-absorb significant quantities of CO2 in a CO2 rich environment (e.g., shifted syngas) and consequently reduce their sulfur absorption capacity, and require higher solvent circulation and regeneration duties while generating undesirable CO2 emissions. Unfortunately, such configurations also produce an acid gas enriched in CO2 that is problematic for a downstream sulfur plant.
Consequently, although many configurations and methods for H2S and CO2 removal from syngas are known in the art, all or almost all of them suffer from various disadvantages. Thus, there is still a need to provide methods and configurations for improved H2S and CO2 removal, especially for syngas with high CO2 content.